This and the referenced inventions are addressed to the related national problems of energy security and air quality. The economy and defense of the United States are vitally dependent upon petroleum, about 40 percent of which is currently imported. Its domestic production is falling and reserves severely depleted. In the recent past it has experienced serious interruptions in overseas sources outside its control, which were accompanied by a sharp escalation in prices.
Much of the petroleum consumption is of such a nature that it cannot be replaced by domestic fuels, such as coal and natural gas. On the other hand, it is possible for major consumers, particularly electric utilities and industry, to convert to domestic fuels. Substitution of natural gas is, in most cases, relatively easy but gas reserves, while temporarily adequate, are not sufficient for large scale petroleum replacement. Moreover, this resource, which is rich in hydrogen, ought to be reserved for uses to which it is uniquely suited, such as home heating and chemical syntheses.
Unless a boiler was originally designed for coal, conversion is comparatively difficult. But domestic supplies of this and similar fossil fuels are abundant and, from this standpoint, national policy should encourage their use, over petroleum and natural gas, wherever possible. There is, however, much opposition on grounds of air pollution, particularly in respect to oxides of sulfur and nitrogen, which are considered responsible for "acid rain".
Strenuous efforts are being put forth in many energy quarters to ameliorate the air pollution associated with coal burning, mainly in the direction of treating raw coals to reduce their sulfur content (beneficiation) and retrofitting existing boilers to minimize their sulfur and nitrogen oxide emissions. While redesign of burners and various limestone injection and scrubbing techniques have lowered emissions somewhat, retrofitting benefits are inherently limited by the fact that, from the standpoint of chemical thermodynamics, conventional combustion pressure (atmospheric) is too low and temperatures, 2700-3200 degrees Fahrenheit (F.), are too high.
Reference U.S. Pat. No. 4,380,960 (B) addresses both pressure and temperature, describing a pressurized combustion of alkalized solid fuel slurry at a temperature not exceeding 1600 F., the formation of both sulfur and nitrogen oxides thereby being drastically reduced. The combustion of this reference is suited to non-polluting boilers and boiler-based combined cycles but the temperature limitation is comparatively unattractive for gas turbines.
Pressurized combustion at controlled temperature is routine practice in the case of gas turbine engines, although essentially limited to premium fuels. These engines comprise an air compressor, a combustor to heat the compressed air by firing a fuel into it and a gas turbine expander to convert heat and pressure into mechanical energy, part of which is used to drive the compressor, the remainder being a useful product. Strictly speaking, only the expander is a turbine but the term "gas turbine" is commonly used to mean the complete engine. They are well established industrial means of supplying power to pipeline pumps and compressors and to generate peak load electricity. More recently, they have come to be regarded as a practical source of base electric load as well. In such cases, heat remaining in the turbine exhaust is generally converted to steam in a Heat Recovery Steam Generator (HRSG). This steam may drive a steam turbine, which can be coupled to a second electric generator, such a combination being a gas turbine-based combined cycle.
Concurrently, gas turbines equipped with HRSGS are enjoying considerable success in light industrial and institutional markets where small to medium amounts of both heat or steam and electricity are required (or can be sold), a practice known as co-generation.
The combustion of common fuels with stoichiometric air creates temperatures so high that even the exotic alloys used in jet and gas turbine engines cannot withstand them, so it is normal for the design to contemplate relatively high amounts of excess air which, by diluting the combustion gases, cools them to a temperature at which the turbine materials (in some cases, with the help of air or steam cooling) retain sufficient strength and creep resistance. Until recently, excess air of 200-300 percent was normal, so that the air compressor had to compress some 3 or 4 times as much air as needed for the combustion itself.
In general, the hot gas which powers a gas turbine engine is produced by firing the fuel directly into compressed air so that the turbine is exposed to a mixture of hot air and combustion products. An alternative is the externally (or indirect) fired gas turbine in which the fuel is burned in a furnace or fluidized bed and heat therefrom transferred to the compressed air through heat exchange surface. The turbine then sees only hot air and is not exposed to combustion products. Emission control problems are transferred to the flue gas from the furnace or fluidized bed.
Gas turbines developed specifically for industrial and utility service are in widespread use, but most of the recent advances have arisen from intensive developments in aircraft jet engines, particularly the capability to withstand higher turbine inlet temperatures. It has proved practical and economically attractive to adapt a jet engine to produce hot, pressurized gas which serves as the driving fluid for a power recovery turbine, whose shaft delivers mechanical energy to an electrical generator or other use.
Although the heat (and oxygen) in turbine exhaust is capable of generating a substantial amount of steam, it has been conventional practice to expand the combustion gases and steam in separate turbines, with separate generators. That is because steam can be condensed so as to create a vacuum, substantially increasing the expansion ratio and, therefore, the recoverable energy. If the steam had been combined with the combustion gases, the mixture could have been expanded no further than atmospheric pressure.
More recently, new blade materials and blade and nozzle cooling techniques are permitting turbine inlet temperatures above 2000 F. These developments have upset the old rationale for keeping combustion gases and steam separate. If steam is injected into the combustor to moderate the temperature, less excess air is required and less horsepower consumed to compress it. The higher turbine inlet temperature offsets the loss (for the steam component) of expansion ratio. Only one turbine-generator set is required. The acronym for a steam injected gas turbine is STIG.
Moreover, compression ratios are going up. The jet engine-derived General Electric LM-5000, already in service, has a combustion pressure of about 400 psi. A LM-8000 model, having a combustion pressure of about 500 psi, is on the drawing boards. A consortium of Japanese companies are reported to be developing a high temperature, high pressure turbine for combined cycle service with a combustion pressure of around 800 psi.
Heat of compression can make air very hot, creating problems of thermal expansion and loss of efficiency. Early jet engines used water injection to control air compressor temperatures when maximum power was required. When air (or other gas) is compressed industrially, beyond a compression ratio of roughly 6 or 7, it has long been the practice to cool it between stages (a stage being used herein to mean a contiguous series of rotors and stators in the same case) by exchange with cooling water (intercooling) . within the last several years some turbochargers for automotive engines (a gas turbine adaptation) have used intercoolers. With the new higher compression ratios, gas turbines, such as the LM-8000, will necessarily employ intercooling, an intercooled steam injected gas turbine being referred to as an ISTIG. A combustion pressure of the order of 800 psi could entail intercooling more than once.
If it is considered acceptable or desirable to inject steam into a gas turbine combustor there would be no theoretical objection to performing the intercooling by water injection (as in early jet engines) since the vaporized water would merely add to the steam content. This is, in fact, being done although the quality of the water has to be carefully monitored. An alternative is direct contact, preferably counter-current, with sufficient water to cool the gas to an approach to water temperature.
Technical literature has treated "STIG" and "ISTIG" as generic terms although they are registered trademarks of the General Electric Co.
Just as the higher compression ratios require and benefit from intercooling, so can the similarly high expansion ratios benefit from interstage reheating. Gas turbines with both intercooling and reheating are on the drawing boards.
Early gas turbine engines required clean gaseous or distillate fuels. Considerable progress has been made in adapting heavy duty designs to certain less expensive residual fuels. The newer high temperature, high ratio aero-derived machines are, at present, limited to natural gas or clean distillate fuel, but the U.S. Department of Energy is contributing substantial support toward the development and testing of coal-water slurry-fired combustion systems for gas turbine engines, including the advanced aero-derivitives. Operating experience with such machines remains limited to premium fuels.
Adapting the simple gas turbine (leave alone a STIG or ISTIG) to burn coal is a formidable undertaking. In the 1950's and 60's, Bituminous Coal Research, Inc. mounted a determined, but unsuccessful, program to accomplish this objective. Similar attempts were made in Canada and Australia. Among the most stubborn problems have been erosion by ash particles, corrosion by vaporized coal salts and deposits on the sensitive turbine blades. Another is control of emissions, particularly sulfur and nitrogen oxides.
Fueling gas turbines with coal-water slurries is an outgrowth of the extensive research and testing in recent years for firing conventional boilers with Coal-Water Fuel (CWF), a highly beneficiated, concentrated, stabilized slurry containing about 30 percent water. CWFs are frequently proprietary and, according to the technical literature, cost at least twice as much as the coal from which they are made.
The erosion problem is being attacked on several fronts: the oldest method is to separate ash particles from combustion products by one of the known gas-solids separating devices, the most common being filters of various types and cyclone separators of various configurations. Newer approaches contemplate removing as much of the ash as possible by strenuous beneficiation and grinding the fuel particles so fine that they follow the flow path of the gas, rather than impinging on blade surfaces.
Conventionally, gas turbine combustors are closely coupled with, and mounted on the same base, or frame, as the compressor and turbine(s). Such an assembly is referred to as a gas turbine set. Manufacturers would like to extend this practice to firing coal slurries, but the difficulty and space requirements of managing particulates is such that "off-base" or "off-frame" combustors, requiring transition pieces to extract compressed air from, and return hot gas to, the turbo-machinery, are also being considered.
Coal beneficiation is also being directed toward minimizing the sulfur in the slurry, thereby decreasing sulfur dioxide emissions. In some cases, this is sufficient for current regulations but not good enough to meet the stricter standards that environmentalists would like to have enacted. This method can be supplemented by blending ground lime or limestone into the coal slurry--at the expense of increasing the solids which must be separated and/or tolerated by the turbine.
Test firing of coal slurries reported so far is limited to static simulators. Early results indicate relatively severe deposits which are only partly removed by periodic abrasive and water injections (as used with heavy duty turbines burning residual fuel oil). The coal slurry-fired turbine, as heretofore conceived, appears to have a long way to go before it approaches the efficiency and reliability of its natural gas-fired equivalent.
Moderation of combustion temperatures by steam injection holds the formation of nitrogen oxides from natural gas to quite reasonable levels (apparantly lower than equilibrium) but, should the STIGs and ISTIGs eventually prove capable of burning coal slurry, NOx emissions may be a problem.
However, methods of controlling the emission of nitrogen oxides from conventional boilers are coming into commercial use. These methods employ the injection into the flue gas of nitrogen oxide scavengers, such as ammonia and urea solution. When a catalyst is used to promote the reactions, the process is known as Selective Catalytic Reduction (SCR) and, when carried out without catalyst, Selective Non-catalytic Reduction (SNR). According to the literature, one SNR installation is able to achieve a nitrogen oxides reduction of 35 to 70 percent. This installation is meeting a local emission regulation of 225 ppm. In other SNR installations reductions of 60-80 percent are being realized.
U.S. Pat. No. 4,466,241 (Inui et al) describes a waste heat recovery boiler (HRSG) for the exhaust of a gas turbine in which the steam generation surface is divided into two sections with injection of scavenging agent and beds of catalyst (SCR) between sections.
Rail transport of solid fuels from source to point of use adds substantially to their cost. For many years pipeline transport as a slurry in water has appeared to be an attractive alternative. There is one successful U.S. coal slurry pipeline; at destination the slurry is dewatered and dried for pulverized coal firing. It is to be noted that pipeline experience is with a simple slurry containing about 50 percent water so that, to convert it into CWF, dewatering, particle sizing and the addition of chemical additives are required. The surplus slurry water would usually present a disposal problem.
Traditionally, solid materials have been charged to pressurized processes by means of a plurality of "lock hoppers", which are intermittently filled, pressurized, discharged into the process and depressurized, before repeating the cycle. This cumbersome and inefficient method is giving way to charging the solids as a liquid slurry. Similarly, lock hoppers are conventionally used to remove a solid product from a pressurized process--ash (or "lash", a mixture of ash and spent limestone) in the case of pressurized combustions. Not only is it difficult to recover useful heat from hot powdered ash, or lash, but the system is expensive and wastes the pressure energy of the pressurizing gas. That bled off durinq depressurizing usually requires a bag filter or similar control for the dust it carries.
A recognized advantage of gas turbines and other forms of pressurized combustion, for electricity generation, is that units of significant capacity (100-400 Megawatts) are sufficiently compact to be shop fabricated (referred to as "modular construction"), whereas conventional boilers are so large they have to be fabricated onsite. Shop fabrication, where facilities and experienced labor and supervision are available, is both faster and less expensive than field fabrication. Both capital cost and construction time are significant factors in the cost of electricity.
Additional background may be found in the specification of the parent case.